Methods and compositions for diversion during enhanced oil recovery

ABSTRACT

A method for isolating a first region and a proximate second region of a subterranean formation is disclosed that includes introducing an asphaltene composition into the first region of the subterranean formation, the asphaltene composition including asphaltene dissolved in a solvent, and after introducing the asphaltene composition, introducing an aqueous composition to the first region to precipitate the asphaltene in the first region. The precipitated asphaltene forms a barrier that isolates the second region from at least a portion of the first region.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a divisional application of U.S. patent applicationSer. No. 15/897,474 filed Feb. 15, 2018, the entire disclosure of whichis hereby incorporated herein by reference.

TECHNICAL FIELD

The present disclosure relates to natural resource well drilling andhydrocarbon production and, more specifically, to methods andcompositions for diversion during enhanced oil recovery treatments.

BACKGROUND

The discovery and extraction of hydrocarbons, such as oil or naturalgas, from subterranean formations, may be impeded for a variety ofreasons, such as inherently poor permeability or damage to theformation. The production rate of hydrocarbons from ahydrocarbon-producing region of the formation may be reduced compared tothe expected production rate. In these instances, methods for obtainingenhanced oil recovery from the hydrocarbon-producing regions of theformation can be utilized to improve hydrocarbon production. EnhancedOil Recovery (EOR) methods may include chemical flooding of theformation using alkaline or micellar-polymer, miscible displacement ofthe hydrocarbons left in pore space using carbon dioxide injection orhydrocarbon injection, and thermal recovery using steamflood or in-situcombustion. The optimal application of each type depends on formationtemperature, pressure, depth, net pay, permeability, residual oil andwater saturations, porosity, and fluid properties of the oil, such asspecific gravity and viscosity. However, in some cases, treatmentmaterials used in EOR methods may flow out of the hydrocarbon-producingregion in which the EOR treatment is being conducted and into otherregions of the formation. Flow of treatment materials into other regionsof the formation can result in loss of treatment materials and anincrease in the quantity of treatment materials required to conduct theEOR treatment.

SUMMARY

A continuing need exists for methods and compositions for producingbarriers for diverting treatment materials during EOR treatments. Thepresent disclosure is directed to compositions and methods for divertingtreatment materials used in EOR treatment methods into target regions ofthe formation and restricting the flow of these treatment materials toother regions of the formation.

In accordance with one or more embodiments of the present disclosure, amethod for isolating a first region and a proximate second region of asubterranean formation is disclosed. The method includes introducing anasphaltene composition into the first region of the subterraneanformation, the asphaltene composition including asphaltene dissolved ina solvent. After introducing the asphaltene composition, the methodincludes introducing an aqueous composition to the first region toprecipitate the asphaltene in the first region, where the precipitatedasphaltene forms a barrier that isolates the second region from at leasta portion of the first region.

In accordance with other embodiments of the present disclosure, acomposition for a subterranean barrier is disclosed. This compositionincludes asphaltene dissolved in a solvent that includes at least onealkyl alcohol, at least one alkyl aromatic, and at least one halogenatedhydrocarbon.

Additional features and advantages of the described embodiments will beset forth in the detailed description which follows. The additionalfeatures and advantages of the described embodiments will be, in part,readily apparent to those skilled in the art from that description orrecognized by practicing the described embodiments, including thedetailed description which follows as well as the drawings and theclaims.

BRIEF DESCRIPTION OF THE DRAWINGS

The following detailed description of specific embodiments of thepresent disclosure can be best understood when read in conjunction withthe following drawings, where like structure is indicated with likereference numerals and in which:

FIG. 1 schematically depicts a formation of a barrier for diversion oftreatment materials in a subterranean formation, according to one ormore embodiments described in this disclosure;

FIG. 2 graphically depicts the relationship between viscosity (y-axis)and shear rate (x-axis) for various concentrations of asphaltenedissolved in a solvent, according to one or more embodiments describedin this disclosure;

FIG. 3 graphically depicts the pressure (y-axis) as a function of time(x-axis) during flood testing of a core plug sample injected with anasphaltene composition, according to one or more embodiments describedin this disclosure;

FIG. 4 schematically depicts a formation of a barrier for diversion oftreatment materials in a subterranean formation, according to one ormore embodiments described in this disclosure; and

FIG. 5 schematically depicts a barrier for diversion of treatmentmaterials in a subterranean formation, according to one or moreembodiments described in this disclosure.

DETAILED DESCRIPTION

Recitations in the present disclosure of “at least one” component,element, constituent, compound, or other feature, should not be used tocreate an inference that the alternative use of the articles “a” or “an”should be limited to a single component, element, constituent, compound,or feature. For example, “an alkyl alcohol” may refer to one alkylalcohol or more than one alkyl alcohol.

A formation is the fundamental unit of lithostratigraphy. As used in thepresent disclosure, the term “formation” refers to a body of rock thatis sufficiently distinctive and continuous from the surrounding rockbodies that the body of rock can be mapped as a distinct entity. Aformation is, therefore, sufficiently homogenous to form a singleidentifiable unit containing similar rheological properties throughoutthe formation, including, but not limited to, porosity and permeability.A single formation may include different regions, where some regionsinclude hydrocarbons and others do not. To produce hydrocarbons from thehydrocarbon regions of the formation, production wells are drilled to adepth that enables these hydrocarbons to travel from the subterraneanformation to the surface. This initial stage of production is referredto as “primary recovery.”

In primary recovery, natural formation energy, such as gasdrive,waterdrive, or gravity drainage, displaces hydrocarbons from theformation into the wellbore and up to the surface. Initially, theformation pressure may be considerably greater than the downholepressure inside the wellbore. This differential pressure may drivehydrocarbons toward the wellbore and up to surface. However, as theformation pressure decreases because of hydrocarbon production, thedifferential pressure also decreases. To reduce the downhole pressure,or to increase the differential pressure to increase hydrocarbonproduction, an artificial lift system may be implemented, such as a rodpump, an electrical submersible pump, or a gas-lift installation.Production using artificial lift is considered primary recovery. Theprimary recovery stage reaches its limit when the formation pressure isreduced to the point that the hydrocarbon production rates are no longereconomical or when the proportions of gas or water in the productionstream increase to the point that further primary recovery is no longereconomical. During primary recovery, only a minority percentage of theinitial hydrocarbons in the formation are extracted (typically around 10percent (%) by volume for hydrocarbon formations).

During a second recovery stage of hydrocarbon production, an externalfluid such as water or gas may be injected into the formation throughinjection wells positioned in rock that is in fluid communication withproduction wells. As used in this disclosure, the term “injection well”refers to a well in which fluids are injected into the formation ratherthan produced. The purpose of secondary recovery is to maintainformation pressure and to displace hydrocarbons toward the wellbore. Thesecondary recovery stage reaches its limit when the injected fluid(water or gas) is produced in considerable amounts from the productionwells and the production is no longer economical. The successive use ofprimary recovery and secondary recovery in a hydrocarbon formationproduces, on average, 15% to 40% by volume of the original hydrocarbonsin place. This indicates that a significant amount of hydrocarbonsremains in the formation after primary and secondary recovery. EORtechniques can be used during, or after, primary or secondary recoveryto increase the hydrocarbon yield from the formation. Injection wellsare typically used for the primary objective of maintaining formationpressure through secondary recovery. However, injection wells may alsobe used in EOR treatments to inject treatment materials, diversionmaterials, or both.

At any time during production, EOR techniques may be used to improvehydrocarbon displacement in the formation and increase fluid flow fromthe formation to the production well. “EOR” refers to varioussupplementary recovery techniques utilized for the purpose of increasingthe hydrocarbon yield of a formation. As described previously in thisdisclosure, EOR treatments may use various physical and chemicaltechniques to alter the original properties of the hydrocarbons. EOR mayimprove hydrocarbon displacement in the formation and increase fluidflow from the formation to the production well. In some embodiments, EORmay include injecting treatment materials into the formation to displacehydrocarbons in the hydrocarbon-producing region. However, thesetreatment materials may flow into other regions of the formation thatmay not be hydrocarbon-producing regions, which may result in loss oftreatment materials. This loss of treatment materials may further resultin an increase in the quantity of the treatment materials required toconduct the EOR treatments.

Loss of treatment materials during EOR may be reduced by using a meansof diversion. As used in this disclosure, the term “diversion” refers toa process of forming a barrier in the formation to at least partiallyisolate a region of the formation from other regions of the formation.For example, in some embodiments, a barrier may be formed in theformation to isolate a region undergoing EOR from the other regions ofthe formation and to prevent or reduce the flow of treatment materialsfrom the region undergoing EOR to other regions of the formation.Producing a barrier in the formation may enable treatment materials tobe focused on the hydrocarbon-producing regions undergoing EOR treatmentand may reduce loss of treatment materials to other regions of theformation. In some embodiments, the barrier formed during diversion maybe temporary. This may enable a well to produce from that region whenthe EOR treatment is complete.

There are two main categories of diversion: chemical diversion andmechanical diversion. Chemical diversion includes the use of a chemicalagent to achieve diversion during EOR. Some examples of conventionaldiversion materials may include, but are not limited to, benzoic acid,oil-soluble resins, rock salt, gels, foams, cements, or combinations ofthese. Some conventional diversion materials, including gels and foams,have a limited time frame for use. Gels, foams, and cement have alimited time frame during which they may be pumped into the formation,relating to the set time and the cure time it takes for the gel, foam,or cement to transform into a solid which can no longer be pumped intothe formation. There is also a limited time frame for which gels andfoams form an effective barrier in the formation before breakdownoccurs. Additionally, the greater viscosities of conventional gels,foams, and cements, compared to the compositions of the presentdisclosure, may limit the distance into the formation that theseconventional diversion materials can be injected. Further, the amount ofsolids present in some diversion materials, such as cement compositionsfor example, makes injection of these diversion materials intoformations having small pore volumes difficult or impossible.Furthermore, the costs associated with these conventional diversionmaterials may be prohibitive, especially when the diversion materialsare purchased and used in large quantities, as is typical.

The present disclosure is directed to methods for performing diversionduring EOR, in particular to methods for isolating a first region and aproximate second region of a subterranean formation. The methods mayinclude introducing an asphaltene composition into the first region ofthe subterranean formation. The asphaltene composition may includeasphaltene dissolved in a solvent. The asphaltene dissolves in thesolvent to produce a fluid solution having a viscosity that enables theasphaltene composition to be injected into the formation, evenformations with small pore volumes. The methods may further include,after introducing the asphaltene composition, introducing an aqueouscomposition to the first region in order to precipitate the asphaltenein the first region. As described subsequently in this disclosure, theasphaltene is less soluble in the aqueous composition compared tosolubility in the solvent, which causes the asphaltene to precipitateout of the liquid to form a solid precipitate within the formation. Theprecipitated asphaltene may form a barrier that isolates or separatesthe second region from at least a portion of the first region.

Referring now to FIG. 1, an example installation for conducting EOR isillustrated. As shown in FIG. 1, the installation may include a diverterinjection well 100, an EOR injection well 110, and a production well120, all of which may be in fluid communication with a subterraneanformation 190. As shown in FIG. 1, the subterranean formation 190includes a first region 160 and a proximate second region 180. Thebarrier 170 formed by precipitation of the asphaltene in the firstregion 160, according to the methods of the present disclosure, mayisolate at least a portion of the proximate second region 180 from thefirst region 160. Although the barrier 170 is depicted in FIG. 1 asimpeding horizontal flow between the proximate second region 180 and thefirst region 160, the method and compositions described in thisdisclosure may also be used to impede multidirectional flow, such asvertical flow or combinations of vertical and horizontal flow, forexample.

Among other benefits, the asphaltene composition does not have a limitedtime frame for use. The asphaltene composition does not have a set timeor cure time limiting the time available to pump the asphaltenecomposition into the formation, which may enable the asphaltenecomposition to be pumped longer and therefore travel farther into theformation. Furthermore, the asphaltene precipitates out of solution whenthe aqueous composition is introduced into the formation and remains inplace as a barrier until the solvent is introduced into the formationagain and the asphaltene dissolves back into solution. Therefore, timeis not a limiting factor, and the asphaltene will function as a barrierfor as long as necessary. The asphaltene composition also has a lesserviscosity than conventional diversion materials, which enables theasphaltene to travel a farther distance into the formation duringinjection compared to the conventional diversion materials. Asphaltenemay be a material recovered as a by-product of hydrocarbon processing.For example, the asphaltene may precipitate out of the hydrocarbonstreams as the result of pressure drop, turbulent flow, solution carbondioxide, injected condensate, mixing of incompatible crude oils, orother conditions or materials that break the stability of the asphaltenein the hydrocarbon stream during hydrocarbon processing. Utilizingasphaltene as a diversion material in EOR may provide a beneficial usefor a by-product recovered from hydrocarbon processing, which may resultin recycling and conserving valuable resources. Asphaltene is a readilyavailable material in hydrocarbon processing. Therefore, utilizing theasphaltene for diversion materials during EOR may reduce costs forproducing diversion barriers compared to conventional diversionmaterials. Other benefits may be realized by the methods andcompositions described in this disclosure.

As previously discussed in this disclosure, the asphaltene compositionincludes asphaltene dissolved in a solvent. Asphaltene is an organicmaterial that includes aromatic and naphthenic ring compounds and maycontain nitrogen, sulfur, and oxygen compounds or functional groups. Theasphaltene fraction of crude oil is not soluble in straight-chainhydrocarbon solvents such as pentane or heptane. Asphaltenes are presentin carbonaceous materials such as crude oil and may be recovered fromhydrocarbon processing operations as a byproduct or removed from thecrude oil or intermediate hydrocarbon streams upstream of hydrocarbonprocessing operations. Asphaltene includes the portion of a carbonaceousmaterial that is not soluble in n-heptane but is soluble in toluene.Asphaltenes may be present in other carbonaceous materials, such as coalor bitumen, for example. Asphaltenes may include carbon, hydrogen,nitrogen, oxygen, and sulfur, as well as trace amounts of vanadium andnickel. In some embodiments, the asphaltenes may have a molar ratio ofcarbon to hydrogen of from 1:1 to 1:1.4, such as from 1:1.1 to 1:1.3,depending on the asphaltene source. In some embodiments, the asphaltenesmay have a molecular mass of from 400 daltons (u) to 1500 u.

Asphaltene can be operationally defined as hydrocarbon compounds thatare insoluble in n-heptane and soluble in toluene. Asphaltene isnon-soluble in water and other aqueous compositions and will remain insolid form when combined with water and other aqueous compositions. Thenon-solubility of asphaltene in water or other aqueous compositionsmeans that even at increased temperature, the amount of asphaltenedissolved in the water or other aqueous composition is less than 0.01weight percent (wt. %). However, asphaltenes are soluble in lightaromatic solvents such as benzene and toluene and other light organicsolvents, such as organic alcohols and halogenated hydrocarbons, forexample. As previously discussed in this disclosure, the asphaltenecomposition includes asphaltene dissolved in a solvent. The dissolvedasphaltene may be precipitated out of the solvent solution byintroducing an aqueous solution to the asphaltene composition. As theaqueous solution gradually dilutes the solvent, the solubility of theasphaltene in the solvent is reduced, which causes precipitation of theasphaltene out of solution to form a solid precipitate. This isevidenced by the viscosity data presented in FIG. 2 and discussedsubsequently in this disclosure in Example 1. It was found that thedifference in solubility of the asphaltene in the solvent compared tothe solubility of asphaltene in water can be used to form a barrier fordiversion in the context of EOR. For example, the greater solubility ofthe asphaltene in the solvent may enable the asphaltene composition tobe injected deep into the formation, even if the formation includessmall pore sizes. Then, once the asphaltene composition is in positionin the formation, water or other aqueous composition can be injected tomix with the asphaltene composition in the formation. Because asphalteneis non-soluble in water and other aqueous compositions, increasing theconcentration of water relative to the concentration of the solventcauses the asphaltene to precipitate in place within the formation toform the barrier. Utilizing this method in the context of EOR diversionenables the solid asphaltene to form the barrier in the formation, whichmay be used as a diversion in EOR treatments.

The solvent may be an organic solvent. In some embodiments, the solventmay include one or more than one of an alkyl alcohol, an alkyl aromatic,a halogenated hydrocarbon, or combinations of these. The alkyl alcoholmay be a straight-chain, branched, or cyclic alkyl alcohol having from 1to 20 carbon atoms, such as from 1 to 15, from 1 to 12, or from 1 to 10carbon atoms. The alkyl alcohol may be a saturated alkyl alcohol or anunsaturated alkyl alcohol. The alkyl alcohol may have one or more thanone hydroxyl group, such as 1, 2, 3, 4, or more than 4 hydroxyl groups.Examples of alkyl alcohols may include, but are not limited to methanol,ethanol, propanol, isopropanol, butanol, hexanol, heptanol, octanol, orcombinations of these. Other organic alcohols may also be suitable foruse in the solvent. In some embodiments, the solvent may include aplurality of alkyl alcohols. In some embodiments, the solvent mayinclude from 5 wt. % to 50 wt. % alkyl alcohol based on the total weightof the solvent, such as from 5 wt. % to 45 wt. %, from 5 wt. % to 40 wt.%, from 5 wt. % to 35 wt. %, from 5 wt. % to 30 wt. %, from 10 wt. % to50 wt. %, from 10 wt. % to 45 wt. %, from 10 wt. % to 40 wt. %, from 10wt. % to 35 wt. %, or from 10 wt. % to 30 wt. % alkyl alcohol. In someembodiments, the alkyl alcohol may be methanol. In some embodiments, thesolvent may include from 5 wt. % to 50 wt. % methanol based on the totalweight of the solvent.

The alkyl aromatic may include one or a plurality of aromatic rings andone or a plurality of alkyl groups. The alkyl groups may be straight orbranched and may be saturated or unsaturated. The alkyl may have from 1to 20 carbon atoms, such as from 1 to 15, from 1 to 12, or from 1 to 10carbon atoms. In some embodiments, the solvent may include a pluralityof alkyl aromatics. Alkyl aromatics may include, but are not limited to,toluene, ethylbenzene, p-xylene, m-xylene, o-xylene, mesitylene, durene,2-phenylhexane, hexamethylbenzene, other alkyl aromatics, orcombinations of these. In some embodiments, the solvent may include from5 wt. % to 50 wt. % alkyl aromatic based on the total weight of thesolvent, such as from 5 wt. % to 45 wt. %, from 5 wt. % to 40 wt. %,from 5 wt. % to 35 wt. %, from 5 wt. % to 30 wt. %, from 10 wt. % to 50wt. %, from 10 wt. % to 45 wt. %, from 10 wt. % to 40 wt. %, from 10 wt.% to 35 wt. %, or from 10 wt. % to 30 wt. % alkyl aromatic. In someembodiments, the alkyl aromatic may be toluene, xylene, or both. As usedin this disclosure, the term “xylene” refers a composition consisting ofp-xylene, o-xylene, m-xylene, or any combinations of these. In someembodiments, the solvent may include from 5 wt. % to 50 wt. % tolueneand 5 wt. % to 50 wt. % xylene based on the total weight of the solvent.

The halogenated hydrocarbon may be a straight, branched, or cyclichalogenated hydrocarbon having from 1 to 20 carbon atoms and at leastone halogen atom covalently bonded to at least one of the carbon atoms.The halogenated hydrocarbon may also be saturated, unsaturated, oraromatic. Halogens include any of the elements in group 17 of the IUPACperiodic table, which includes fluorine (F), chlorine (Cl), bromine(Br), and iodine (I). In some embodiments, the halogenated hydrocarbonmay be an alkyl halide. Halogenated hydrocarbons may include, but arenot limited to, chloroform, benzotrichloride, bromoform, bromomethane,carbon tetrachloride, chlorobenzene, chlorofluorocarbon, chloromethane,1,1-dichloro-1-fluoroethane, 1,2-dichlorobenzene, 1,1-dichloroethane,1,2-dichloroethane, 1,1-dichloroethene, 1,2-dichloroethene,dichloromethane, 1,2-difluorobenzene, 1,2-diiodoethylene, diiodomethane,fc-75, hexachlorobutadiene, hexafluoro-2-propanol,parachlorobenzotrifluoride, perfluoro-1,3-dimethylcyclohexane,perfluorocyclohexane, perfluorodecalin, perfluorohexane,perfluoromethylcyclohexane, perfluoromethyldecalin, perfluorooctane,perfluorotoluene, perfluorotripentylamine, tetrabromomethane,1,1,1,2-tetrachloroethane, 1,1,2,2-tetrachloroethane,tetrachloroethylene, 1,2,4-trichlorobenzene, 1,1,1-trichloroethane,1,1,2-trichloroethane, trichloroethylene, 1,2,3-trichloropropane,1,1,1-trifluoro-2-chloroethane, 2,2,2-trifluoroethanol,trifluorotoluene, trihalomethane, or combinations of these. In someembodiments, the solvent may include from 40 wt. % to 85 wt. %halogenated hydrocarbon based on the total weight of the solvent, suchas from 40 wt. % to 80 wt. %, from 40 wt. % to 75 wt. %, from 40 wt. %to 70 wt. %, from 40 wt. % to 65 wt. %, from 45 wt. % to 85 wt. %, from45 wt. % to 80 wt. %, from 45 wt. % to 75 wt. %, from 45 wt. % to 70 wt.%, or from 45 wt. % to 65 wt. % alkyl aromatic. In some embodiments, thehalogenated hydrocarbon may be chloroform. In some embodiments, thesolvent may include from 40 wt. % to 85 wt. % chloroform based on thetotal weight of the solvent.

In some embodiments, the solvent may include at least one alkyl alcohol,at least one alkyl aromatic, and at least one halogenated hydrocarbon.In some embodiments, the solvent may consist of or consist essentiallyof at least one alkyl alcohol, at least one alkyl aromatic, and at leastone halogenated hydrocarbon. In some embodiments, the solvent mayinclude at least one of methanol, toluene, xylene, chloroform, orcombinations of these. In some embodiments, the solvent may includemethanol, toluene, xylene, and chloroform. In some embodiments, thesolvent may consist of or consist essentially of methanol, toluene,xylene, and chloroform. For example, in some embodiments, the solventmay include from 5 wt. % to 50 wt. % methanol, from 5 wt. % to 50 wt. %toluene, from 5 wt. % to 50 wt. % xylene, and from 40 wt. % to 85 wt. %chloroform. In some embodiments, the solvent may consist of or consistessentially of from 5 wt. % to 50 wt. % methanol, from 5 wt. % to 50 wt.% toluene, from 5 wt. % to 50 wt. % xylene, and from 40 wt. % to 85 wt.% chloroform. In some embodiments, the solvent may include 15 wt. %methanol, 10 wt. % xylene, 10 wt. % toluene, and 65 wt. % chloroformbased on a total weight of the solvent. Asphaltene is soluble in asolvent including methanol, toluene, xylene, and chloroform, andtherefore, when the asphaltene and the solvent are combined to form theasphaltene composition, the asphaltene composition is in a liquid phase.

The asphaltene composition may include a weight ratio of solvent toasphaltene that results in the asphaltene dissolving in the solvent tothe extent that the asphaltene composition is substantially free ofdissolved solids prior to introducing the asphaltene composition to thefirst region. As used in this disclosure, the term “substantially freeof dissolved solids” refers to the asphaltene composition having lessthan 1.0 percent by weight undissolved solids. In some embodiments, theasphaltene composition may have a weight ratio of solvent to asphaltenethat results in the asphaltene composition having a viscosity in a rangeof from 1 centipoise (cP) to 3500 cP (1 millipascal second (mPa·s) to3500 mPa·s; where 1 cP=1 mPa·s). In some embodiments, the asphaltenecomposition may have a weight ratio of solvent to asphaltene of from 5:1to 20:1. For example, in some embodiments, the asphaltene compositionmay have a weight ratio of solvent to asphaltene of from 5:1 to 18:1,from 5:1 to 15:1, from 5:1 to 12:1, from 7:1 to 20:1, from 7:1 to 18:1,from 7:1 to 15:1, from 7:1 to 12:1. In some embodiments, the asphaltenecomposition may have a weight ratio of solvent to asphaltene of 10:1. Insome embodiments, the asphaltene composition includes 50 grams (g)asphaltene for every 1000 milliliter (ml) of the solvent.

The asphaltene composition may have a viscosity that enables theasphaltene composition to be injected a farther distance into theformation compared to conventional diversion materials. In someembodiments, the asphaltene composition may have a viscosity of from 1cP to 3500 cP (1 mPa·s to 3500 mPa·s). For example, in some embodiments,the asphaltene may have a viscosity of from 1 cP to 3200 cP, from 1 cPto 3000 cP, from 1 cP to 2500 cP, from 5 cP to 3500 cP, from 5 cP to3200 cP, from 5 cP to 3000 cP, from 5 cP to 2500 cP, from 10 cP to 3500cP, from 10 cP to 3200 cP, from 10 cP to 3000 cP, from 10 cP to 2500 cP,from 100 cP to 3500 cP, from 100 cP to 3200 cP, from 100 cP to 3000 cP,or from 100 cP to 2500 cP. In some embodiments, the viscosity of theasphaltene composition at 25° C. may be from 2720 mPa·s at a shear rateof 0.0999 inverse seconds (s⁻¹) to 587 mPa·s at a shear rate of 1000s⁻¹. Not intending to be limited by theory, it is believed that theviscosity of the asphaltene composition may enable the asphaltenecomposition to be injected farther into the subterranean formationcompared to conventional diversion methods that may result in thebarrier being positioned a farther distance into the subterraneanformation compared to barrier formed from other conventional diversionmaterials having greater viscosities.

The asphaltene composition may be a stable solution, meaning that theasphaltene composition has a stable chemical makeup, in which theasphaltene remains dissolved in solution, at a pressure of up to 4000pounds per square inch (psi) and a temperature of up to 200 degreesCelsius (° C.). The precipitated asphaltene may be stable at pressuresof up to 5000 psi and temperatures of up to 400° C., meaning that theprecipitated asphaltene solid has a stable chemical makeup under theseconditions.

Referring again to FIG. 1, in some embodiments, the asphaltenecomposition may be introduced into the first region 160 through adiverter injection well 100. The first region may be a barrier regionbetween the second region and other regions of the formation, and thesecond region may be a hydrocarbon-producing region. The diverterinjection well 100 may be located such that the asphaltene compositionmay be injected into the first region 160 to form the barrier 170between the first region 160 and the second region 180. It iscontemplated that more than one barrier 170 may be formed. For example,the second region 180 may be isolated from two or more regions of aformation by two or more barriers 170. Likewise, it is contemplated thatto form these two or more barriers 170, two or more diverter injectionwells 100 may be used. In some embodiments, the second region 180 may beproximate to the first region 160. The second region 180 may include anEOR injection well 110 and a production well 120 for introducingtreatment materials for EOR and producing hydrocarbons, respectively. Itis contemplated that there may be two or more EOR injection wells 110.It is also contemplated that there may be two or more production wells120 within the second region 180. The EOR injection well 110 and theproduction well 120 may also be located in other, separate regions ofthe formation. In some embodiments, the asphaltene composition may beintroduced into the first region 160 using coiled tubing or a drillstring. In another embodiment, the inlet pressure of the asphaltenecomposition during introduction of the asphaltene composition to thefirst region 160 may be from 2000 to 4000 psi. The inlet pressure may begreater than the reservoir pressure, but less than the formationfracture pressure which depends on the strength of the formation.Formation fracture pressure is the pressure above which the injection offluids will cause the formation to fracture.

In some embodiments, the method may further include preventingprecipitation of the asphaltene at an introduction point of theasphaltene composition to the first region 160. For example, in someembodiments, the method may include introducing a spacer fluid into theformation after introducing the asphaltene composition and beforeintroducing the aqueous composition 130. Introducing the spacer fluidinto the formation may include injecting the spacer fluid through thediverter injection well 100. The spacer fluid may be used to propel theasphaltene composition farther into the formation. As used in thisdisclosure, a spacer fluid refers to a liquid used to physicallyseparate one special-purpose liquid from another. In this case, thespacer fluid maybe used to separate the asphaltene composition from theaqueous composition. Using a spacer fluid may ensure that the asphaltenecomposition does not precipitate at the injection point, or introductionpoint, of the diverter injection well 100. Special-purpose liquids aretypically prone to contamination, so a spacer fluid compatible with eachis used between the two. Therefore, the spacer fluid would be compatiblewith both the asphaltene composition and the aqueous composition. Thespacer fluid may be an oil-based fluid, however various spacer fluidsare contemplated based on the specific industrial application.Parameters governing the effectiveness of a spacer include flow rate,contact time, and fluid properties.

Once the asphaltene composition is positioned within the first region160 of the formation, the method may include introducing the aqueouscomposition 130 into the subterranean formation 190 to precipitate theasphaltene out of the asphaltene composition in the first region 160 toform a barrier 170 between the first region 160 and the second region180. Introducing the aqueous composition 130 into the formation mayinclude injecting the aqueous composition 130 through the diverterinjection well 100. In some embodiments, the aqueous composition 130 mayinclude one or more than one of fresh water, salt water, brine,municipal water, formation water, produced water, well water, filteredwater, distilled water, sea water, other type of water, or combinationsof waters. In some embodiments, the aqueous composition 130 may includewater or a solution containing water and one or more inorganic compoundsdissolved in the water or otherwise completely miscible with the water.In some embodiments, the aqueous composition may contain brine,including natural and synthetic brine. Brine includes water and a saltthat may include calcium chloride, calcium bromide, sodium chloride,sodium bromide, other salts, and combinations of these.

Referring again to FIG. 1, in some embodiments, the method may includeperforming EOR in the proximate second region 180. EOR may be performedonce the aqueous composition 130 has been introduced into the formationand the asphaltene has precipitated out of the asphaltene composition inthe first region 160 and formed a barrier 170 between the first region160 and the second region 180. In some embodiments, the EOR may includeinjecting a treatment composition 140 into the first region 160 from anEOR injection well 110. The barrier 170 formed by the asphalteneprecipitate from the asphaltene composition may maintain at least aportion of the treatment composition 140 in the second region 180. Thebarrier 170 may, therefore, restrict the flow of the treatmentcomposition 140 into other regions of the subterranean formation. Byrestricting the flow of the treatment composition 140, the barrier 170may increase the quantity of treatment composition 140 that enters thesecond region 180, which may result in increasing the quantity ofhydrocarbons 150 that are produced from the second region 180 inproduction well 120.

In another embodiment, the method may further include removing thebarrier 170 from the first region 160 by introducing the solventcomposition to the first region 160. The solvent composition maydisplace the aqueous composition 130 in the first region 160. Bydisplacing the aqueous composition 130, the solvent compositionincreases the solubility of the precipitated asphaltene and dissolvesthe precipitated asphaltene back into solution, forming the barrier 170.This asphaltene composition may then be conveyed from the first region160 to the surface, due to its lesser viscosity, which may result inremoving the asphaltene composition from the subterranean formation 190.

Referring now to FIG. 4, in some embodiments, the first region 160 maybe located vertically above the second region 180, as discussedpreviously. In this embodiment, the method may include introducing theasphaltene composition into the first region 160 through an injectionwell 112, while production well 120 produces hydrocarbons 150 from thesecond region 180. During the introduction of the asphaltenecomposition, the injection well 112 may be mechanically isolated fromthe second region 180 using a packer 132 or any other known isolationmethod. The method may further include introducing the aqueouscomposition 130 into the first region 160 through the injection well 112to precipitate the asphaltene out of the asphaltene composition in thefirst region 160 to form a barrier 170 between the first region 160 andthe second region 180.

Referring to FIG. 5, the method may further include performing EOR inthe proximate second region 180 by introducing the treatment composition140 into the second region 180 through the injection well 112 after thepacker 132 (FIG. 4) has been removed. The barrier 170 formed by theasphaltene precipitate from the asphaltene composition may maintain atleast a portion of the treatment composition 140 in the second region180. The barrier 170 may, therefore, restrict the flow of the treatmentcomposition 140 into other regions of the subterranean formation. Byrestricting the flow of the treatment composition 140, the barrier 170may increase the quantity of treatment composition 140 that enters thesecond region 180, which may result in increasing the quantity ofhydrocarbons 150 that are produced from the second region 180 inproduction well 120. Although the first region 160 is depicted in FIGS.4 and 5 as being located vertically above the second region 180, it isunderstood that, in some embodiments, the first region 160 may also belocated vertically below the second region 180.

EXAMPLES

The following examples illustrate features of the present disclosure butare not intended to limit the scope of the disclosure.

Example 1

To evaluate the effect of water on the asphaltene composition, varyingamounts of asphaltene composition and water were mixed together and theviscosity was measured using an Anton Paar viscometer at roomtemperature and atmospheric pressure at shear rates of from 0.1 persecond (s⁻¹) to 1,000 s⁻¹. The viscosities of the asphaltenecompositions are reported in millipascal seconds (mPa·s). The asphaltenecomposition had a weight ratio of solvent to asphaltene of 10:1. Thesolvent included 15 wt. % methanol, 10 wt. % xylene, 10 wt. % toluene,and 65 wt. % chloroform.

TABLE 1 Viscosity measurements of asphaltene composition and watermixtures at increasing shear rates. 20 ml 15 ml 10 ml 5 ml AsphalteneAsphaltene Asphaltene Asphaltene Compo- Compo- Compo- Compo- sitionsition sition sition Asphaltene 5 ml 10 ml 15 ml 20 ml Composition WaterWater Water Water Shear (201) (202) (203) (204) (205) Rate ViscosityViscosity Viscosity Viscosity Viscosity [s⁻¹] [mPa · s] [mPa · s] [mPa ·s] [mPa · s] [mPa ·s] 0.1 2,720 747 1,710 3,170 1,890 0.147 2,060 7471,700 2,940 1,800 0.215 1,670 748 1,410 2,670 1,580 0.316 1,240 7491,200 2,510 1,150 0.464 1,040 747 1,080 2,290 936 0.681 910 747 1,0202,080 739 1 829 745 977 2,010 536 1.47 771 745 939 1,790 389 2.15 736743 859 1,580 260 3.16 710 739 817 1,430 171 4.64 696 736 805 1,340 80.16.81 685 733 792 1,260 119 10 676 730 782 1,250 79.7 14.7 670 729 7751,210 62.2 21.5 664 728 770 1,200 19.4 31.6 661 726 766 1,140 7.88 46.4657 725 763 1,130 10.3 68.1 652 726 766 1,110 12.4 100 647 728 774 1,0205.23 147 638 723 784 915 4.91 215 629 716 786 562 5.16 316 622 705 784362 5.44 464 617 699 778 280 7.26 681 608 690 767 221 8.94 1,000 587 695739 134 8.67

Referring to FIG. 2, increasing the proportion of water in the mixtureincreased the viscosity of the mixture. More specifically, mixture 202,which included 20 ml asphaltene composition and 5 ml water, hadviscosity less than the viscosity of mixture 203. Mixture 203 included15 ml asphaltene composition and 10 ml water. Likewise, mixture 203 hada viscosity less than the viscosity of mixture 204, except at shearrates greater than 150 s⁻¹. Mixture 204 included 10 ml asphaltenecomposition and 15 ml water. Mixture 205, which included 5 ml asphaltenecomposition and 20 ml water, did not follow this trend. However, it wasobserved that the ratio of water to asphaltene composition in mixture205 was great enough to cause the asphaltene to precipitate out of thesolution and coat the viscometer. Thus, the viscosity measured formixture 205 was considerably less than the other mixtures andapproximated the viscosity of a mixture of water and solvent. Theviscosity of mixture 201, which included only the asphaltenecomposition, ranged from 2720 mPa·s at 0.1 s⁻¹ to 587 mPa·s at 1000 s⁻¹.The viscosity of mixture 202 ranged from 747 mPa·s at 0.1 s⁻¹ to 695mPa·s at 1000 s⁻¹. The viscosity of mixture 203 ranged from 1710 mPa·sat 0.1 s⁻¹ to 739 mPa·s at 1000 s⁻¹. The viscosity of mixture 204 rangedfrom 3170 mPa·s at 0.1 s⁻¹ to 134 mPa·s at 1000 s⁻¹. The viscosity ofmixture 205 ranged from 1890 mPa·s at 0.1 s⁻¹ to 8.67 mPa·s at 1000 s⁻¹.At a shear rate of 10 s⁻¹, the viscosity increases from mixture 201, tomixture 202, to mixture 203, to mixture 204. Not intending to be boundby theory, it is believed that this increasing of viscosity withincreasing water content was caused by increasing precipitation of theasphaltene in the mixtures due to the decreasing solubility of theasphaltene with increasing water content.

Example 2

Example 2 demonstrates the asphaltene precipitating out of theasphaltene composition when the asphaltene composition is diluted withwater. 50 g of solid asphaltene were dissolved in 1000 ml of solvent toform the asphaltene composition. The solvent included 15 wt. % methanol,10 wt. % xylene, 10 wt. % toluene, and 65 wt. % chloroform. Then, 2000ml water was added to the asphaltene composition. The asphalteneprecipitated out of the solution formed by water mixed with theasphaltene composition to form a solid asphaltene precipitate. Afterdecanting the liquids, some of the solid asphaltene precipitate coatedthe inside of the testing container. The solid asphaltene precipitatewas then recovered from the testing container. 60 to 65 wt. % of theinitial solid asphaltene was recovered as solid asphaltene precipitate,or 30 to 32.5 g of the initial 50 g of asphaltene added to theasphaltene composition of Example 2.

Example 3

To investigate how the asphaltene precipitate functions as a barrier foruse in diversion, the asphaltene composition was injected into a coresample and flooded with water. A Coretest system model RPS-812-Z wasused in this experiment. The asphaltene composition had a weight ratioof solvent to asphaltene of 10:1. The solvent included 15% methanol, 10%xylene, 10% toluene, and 65% chloroform. A core plug sample with apermeability of 308 milliDarcys (mD) was selected. The core plug samplewas placed in a core flood system and injected with the asphaltenecomposition at 120° C., 500 psi back pressure, and 1000 psi confinedpressure. Back pressure is the pressure within a system caused by fluidfriction or an induced resistance to flow through the system. Mostprocess facilities require a minimum system pressure to operateefficiently. The back-pressure was created and controlled by a valve setto operate under the desired range of conditions. Confined pressure isthe pressure under which the core plug sample is confined. The core plugsample was then injected with water to flood the pores. FIG. 3 shows thepore pressure of the core plug sample throughout the flood test. FIG. 3illustrates that the pore pressure of the core plug sample rose from 5.9psi at 1 second during the flood test to 585.2 psi at 13 seconds (40.68kilopascals (kPa) at 1 second to 4035 kPa at 13 seconds; where 1psi=6.894757 kPa), which indicates that the permeability of the coresample decreased when the asphaltene precipitated out of solution duringthe water flood. The increase in the pressure during the flood testindicates that the solid asphaltene precipitated within the pores of thecore plug sample to produce a restriction to flow of fluids through thecore plug.

It is noted that one or more of the following claims utilize the term“where” or “in which” as a transitional phrase. For the purposes ofdefining the present technology, it is noted that this term isintroduced in the claims as an open-ended transitional phrase that isused to introduce a recitation of a series of characteristics of thestructure and should be interpreted in like manner as the more commonlyused open-ended preamble term “comprising.” For the purposes of definingthe present technology, the transitional phrase “consisting of” may beintroduced in the claims as a closed preamble term limiting the scope ofthe claims to the recited components or steps and any naturallyoccurring impurities. For the purposes of defining the presenttechnology, the transitional phrase “consisting essentially of” may beintroduced in the claims to limit the scope of one or more claims to therecited elements, components, materials, or method steps as well as anynon-recited elements, components, materials, or method steps that do notmaterially affect the novel characteristics of the claimed subjectmatter. The transitional phrases “consisting of” and “consistingessentially of” may be interpreted to be subsets of the open-endedtransitional phrases, such as “comprising” and “including,” such thatany use of an open ended phrase to introduce a recitation of a series ofelements, components, materials, or steps should be interpreted to alsodisclose recitation of the series of elements, components, materials, orsteps using the closed terms “consisting of” and “consisting essentiallyof.” For example, the recitation of a composition “comprising”components A, B, and C should be interpreted as also disclosing acomposition “consisting of” components A, B, and C as well as acomposition “consisting essentially of” components A, B, and C. Anyquantitative value expressed in the present application may beconsidered to include open-ended embodiments consistent with thetransitional phrases “comprising” or “including” as well as closed orpartially closed embodiments consistent with the transitional phrases“consisting of” and “consisting essentially of.”

As used in the Specification and appended Claims, the singular forms“a”, “an”, and “the” include plural references unless the contextclearly indicates otherwise. The verb “comprises” and its conjugatedforms should be interpreted as referring to elements, components orsteps in a non-exclusive manner. The referenced elements, components orsteps may be present, utilized or combined with other elements,components or steps not expressly referenced.

It should be understood that any two quantitative values assigned to aproperty may constitute a range of that property, and all combinationsof ranges formed from all stated quantitative values of a given propertyare contemplated in this disclosure. The subject matter of the presentdisclosure has been described in detail and by reference to specificembodiments. It should be understood that any detailed description of acomponent or feature of an embodiment does not necessarily imply thatthe component or feature is essential to the particular embodiment or toany other embodiment. Further, it should be apparent to those skilled inthe art that various modifications and variations can be made to thedescribed embodiments without departing from the spirit and scope of theclaimed subject matter.

What is claimed is:
 1. A method for isolating a first region and aproximate second region of a subterranean formation, the methodcomprising: introducing an asphaltene composition into the first regionof the subterranean formation, the asphaltene composition comprisingasphaltene dissolved in a solvent; and after introducing the asphaltenecomposition, introducing an aqueous composition to the first region inorder to precipitate the asphaltene in the first region, where theprecipitated asphaltene forms a barrier that isolates the second regionfrom at least a portion of the first region.
 2. The method of claim 1 inwhich the asphaltene composition has a viscosity of from 1 centipoise(cP) to 3500 cP.
 3. The method of claim 1 in which the asphaltenecomposition has a weight ratio of solvent to asphaltene from 5:1 to20:1.
 4. The method of claim 1 in which an inlet pressure of theasphaltene composition during introduction of the asphaltene compositionto the first region is from 2000 to 4000 pounds per square inch (psi).5. The method of claim 1 in which the solvent includes an alkyl alcohol,an alkyl aromatic, a halogenated hydrocarbon, or combinations of these.6. The method of claim 1 in which the solvent includes methanol,toluene, xylene, and chloroform.
 7. The method of claim 1 in which thesolvent includes: 5 to 50 wt. % methanol; 5 to 50 wt. % xylene; 5 to 50wt. % toluene; and 40 to 85 wt. % chloroform based on a total weight ofthe solvent.
 8. The method of claim 1 in which the aqueous compositionincludes at least one of fresh water, salt water, brine, municipalwater, formation water, produced water, well water, filtered water,distilled water, sea water, other types of water, or combinations ofthese.
 9. The method of claim 1 in which the asphaltene composition issubstantially free of undissolved solids prior to introducing theasphaltene composition to the first region.
 10. The method of claim 1 inwhich the asphaltene composition is a stable solution at a pressure ofat least 5000 psi and a temperature up to 400° C.
 11. The method ofclaim 1 further comprising injecting a spacer fluid after introducingthe asphaltene composition and before introducing the aqueouscomposition.
 12. The method of claim 1 further comprising preventingprecipitation of the asphaltene at an introduction point of theasphaltene composition to the first region.
 13. The method of claim 1 inwhich introducing the asphaltene composition to the first regionincludes injecting the asphaltene composition from an injection wellinto the first region.
 14. The method of claim 1 comprising introducingthe asphaltene composition to the first region using coiled tubing or adrill string.
 15. The method of claim 1 further comprising conductingEOR in the second region that is isolated from at least a portion of thefirst region by the barrier.
 16. The method of claim 15 in which the EORincludes: injecting a treatment composition into the first region froman injection well, where the barrier maintains the treatment compositionin the second region and restricts flow of the treatment compositioninto other regions of the subterranean formation; and recoveringhydrocarbons from the second region.
 17. The method of claim 1 furthercomprising removing the barrier by introducing a solvent composition tothe first region, in which the solvent composition displaces the aqueouscomposition in the first region, which may increase the solubility ofthe asphaltene and dissolving the precipitated asphaltene.